Hydrocarbons, such as oil, may be recovered from hydrocarbon containing formations (or reservoirs) by penetrating the formation with one or more wells, which may allow the hydrocarbons to flow to the surface. A hydrocarbon containing formation may have a natural energy source (e.g. gas, water) to aid in mobilising hydrocarbons to the surface of the wells. For example, water or gas may be present in the formation at sufficient levels to exert pressure on the hydrocarbons to mobilise them to the surface of the production wells. However, reservoir conditions (e.g. permeability, hydrocarbon concentration, porosity, temperature, pressure) can significantly impact on the economic viability of hydrocarbon production from any particular hydrocarbon containing formation. Furthermore, any natural energy sources that exist may become depleted over time, often long before the majority of hydrocarbons have been extracted from the reservoir. Therefore, supplemental recovery processes may be required and used to continue the recovery of hydrocarbons from the hydrocarbon containing formation. Examples of known supplemental processes include waterflooding, polymer flooding, alkali flooding, thermal processes, solution flooding or combinations thereof.
In recent years there has been increased activity in developing new and improved methods of chemical Enhanced Oil Recovery (EOR) for maximising the yield of hydrocarbons from a subterranean reservoir. In surfactant EOR the mobilisation of residual oil saturation is achieved through surfactants which generate a sufficiently (ultra) low crude oil/water interfacial tension (IFT) to give a capillary number large enough to overcome capillary forces and allow the oil to flow (Chatzis & Morrows, 1989, “Correlation of capillary number relationship for sandstone”, SPE Journal, 29, pp 555-562). However, different reservoirs can have very different characteristics (e.g. crude oil type, temperature, water composition—salinity, hardness etc.), and therefore, it is desirable that the structures and properties of the added surfactant(s) be matched to the particular conditions of a reservoir to achieve the required low IFT. In addition, a promising surfactant must fulfil other important criteria such as low rock retention, compatibility with polymer, thermal and hydrolytic stability and acceptable cost (including ease of commercial scale manufacture).
Compositions and methods for EOR utilising an alpha olefin sulfate-containing surfactant component are known (e.g. U.S. Pat. No. 4,488,976 and U.S. Pat. No. 4,537,253). Similarly, compositions and methods for EOR utilising internal olefin sulfonates (IOSs) are also known (see e.g. U.S. Pat. No. 4,597,879). The compositions described in the foregoing patents have the disadvantages that both brine solubility and divalent ion tolerance are insufficient under certain reservoir conditions. Hence, it would be advantageous if the reduction in IFT which can be achieved in relatively high salinity and/or hardness conditions could be improved. U.S. Pat. No. 4,979,564 describes the use of IOSs in a method for EOR using low tension viscous water flood. An example of a commercially available material described as being useful was ENORDET® IOS 1720, a product of Shell Oil Company identified as a sulfonated C17-20 internal olefin sodium salt. This material has a low degree of branching. U.S. Pat. No. 5,068,043 describes a petroleum acid soap-containing surfactant system for waterflooding wherein a cosurfactant comprising a C17-20 or a C20-24 IOS was used. In “Field Test of Cosurfactant-enhanced Alkaline Flooding” by Falls et al., Society of Petroleum Engineers Reservoir Engineering, 1994, the authors describe the use of a C17-20 or a C20-24 IOS in a waterflooding composition with an alcohol alkoxylate surfactant to keep the composition as a single phase at ambient temperature without affecting performance at reservoir temperature significantly. The water had a salinity of about 0.4 wt % sodium chloride. However, these materials, used individually, also have disadvantages under relatively severe conditions of salinity and hardness.
In WO 2009/100228 there is described a method for EOR in different high salinity reservoir conditions. When the salinity is from 2 wt % to 4 wt %, the hydrocarbon recovery composition comprises a blend of a C20-24 IOS and a C24-28 IOS, wherein the weight ratio of the C20-24 IOS to the C24-28 IOS is from 90:10 to 70:30; and when the salinity is from 4 wt % to 13 wt % the hydrocarbon recovery composition comprises a blend of a C20-24 IOS and a C15-18 IOS, wherein the weight ratio of the C20-24 IOS to the C15-18 IOS is from 90:10 to 70:30.
Although some surfactant compositions may have application as oil recovery compositions over broad salinity ranges, it is known that, for many surfactant compositions, as salinity increases the oil (or water) solubilisation parameter of the surfactant composition may proportionally decrease. Therefore, at higher salinities, the amount of hydrocarbon mobilised by the available recovery compositions may significantly reduce. Therefore, it would be desirable to have a hydrocarbon recovery composition for EOR that has applicability over a range of salinities and/or has a relatively high oil solubilisation parameter that is not significantly reduced over a significant proportion of its applicable salinity range.
Accordingly, the present invention seeks to overcome or at least alleviate one or more of the problems in the prior art.